The statements made herein provide background information related to the present disclosure and may or may not constitute prior art.
Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on well monitoring and maintenance. Once more, perhaps even more emphasis has been directed at initial well architecture and design. All in all, careful attention to design, monitoring and maintenance may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured.
In the case of well monitoring and logging, mostly minimally-invasive applications may be utilized which provide temperature, pressure and other production related information. By contrast, well design, completion and subsequent maintenance, may involve a host of more direct interventional applications. For example, perforations may be induced in the wall of the well, debris or tools and equipment removed, etc. In some cases, the well may even be designed or modified such that entire downhole regions are isolated or closed off from production. Such is often the case where an otherwise productive well region is prone to produce water or other undesirable fluid that tends to hamper hydrocarbon recovery.
Closing off well regions as noted above is generally achieved by way of setting one or more inflatable packers. Such packers may be set at downhole locations and serve to seal off certain downhole regions from other productive regions. Delivering, deploying and setting packers for isolation may be achieved by way of coiled tubing, or other conventional line delivery application. The application may be directed from the oilfield surface and involve a significant amount of manpower and equipment. Indeed, the application may be fairly sophisticated, given the amount of precision involved in packer positioning and inflation. As noted further below, proper packer inflation, in particular may be quite challenging, given the high and variable temperature and pressure extremes often present downhole which can affect fluid inflation.
Unfortunately, isolation of a downhole region generally requires positioning and deployment of at least two packers. For example, where a perforated region of a well is to be isolated, packers may be deployed at either side of downhole perforations. This is due to the fact that it is unlikely that the perforated downhole region is of such a limited size so as to be fully occluded by deployment of a single conventionally sized packer (i.e. generally less than about two feet in length). As a result, cutting off the noted downhole region requires multiple packer delivery applications, thus increasing expenses associated with the manpower, equipment and, perhaps most importantly, time, are significantly increased.
In addition to the expenses associated with packer delivery and deployment applications, the effectiveness of packer isolation itself is often less than desirable. For example, once a well region is identified for isolation, such as where water production is detected, the isolation is generally sought for the remaining life of the well. As a practical matter, this means that packer isolation of the region may be desirable for up to twenty years or more. However, for the reasons described below, it is unlikely that packer isolation of such a region would be reliable for such durations.
Changing well conditions may have a significant impact on proper packer inflation and sealing off of the well region. More specifically, as pressure and temperature rise, the fluid employed for packer inflation, as well as the packer material itself, may tend to be more expansive. In one sense, this may promote sealing of the packer at the well wall. However, this may also lead to bursting of the packer, complete failure of the isolation, and even the undesirable introduction of packer inflation fluid to the downhole environment. Alternatively, as pressures and temperatures drop, such fluid and materials may contract. Thus, a once properly sealing packer may ultimately lose its seal and fail to provide the desired isolation. Once more, fairly dramatic variability in pressure and temperature are not uncommon to the downhole environment. As such, it is not uncommon for a properly set packer to later fail due to bursting or contraction as a result of the dynamic downhole conditions.
Attempts have been made to address the dynamic condition of downhole pressure swings. Indeed, a whole host of pressure compensation tools and techniques have been developed and incorporated into many state of the art packer assemblies. Unfortunately, such techniques substantially fail to account for downhole temperature swings which may play just as large a role in packer failure. Furthermore, such techniques fail to address expenses associated with the requirement for multiple packer delivery applications over the course of isolating a single downhole region.
Indeed, each delivery application itself faces its own set of challenges. These may include the possibility of premature inflation or other hazards associated with the deployment of the packer via fluid means. Nevertheless, as a practical matter, current techniques for isolation of single downhole well region are substantially limited to the employment of multiple packer delivery applications involving such fluid inflation.